Seismic data processing

ABSTRACT

A method for seismic data processing can include obtaining seismic data acquired based upon trigger times and not based upon positions of triggered source elements. The seismic data can include near-continuously recorded seismic data in split records. The split records can be spliced together into a single near-continuous record to produce a trace with seismic data from a single acquired line. The seismic data can be processed by performing a spatial shift for each of a number of time samples to correct for motion of a number of seismic receivers.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application61/979,247, filed Apr. 14, 2014, which is incorporated by reference.

BACKGROUND

In the past few decades, the petroleum industry has invested heavily inthe development of marine seismic survey techniques that yield knowledgeof subterranean formations beneath a body of water in order to find andextract valuable mineral resources, such as oil. High-resolution seismicimages of a subterranean formation are helpful for quantitative seismicinterpretation and improved reservoir monitoring. For a typical marineseismic survey, a marine seismic survey vessel tows one or more seismicsources below the surface of the water and over a subterranean formationto be surveyed for mineral deposits. Seismic receivers may be located onor near the water bottom, such as being fixed on the water bottom oranchored so as to be near the water bottom, on one or more streamerstowed by the source vessel, or on one or more streamers towed by anothervessel. The source vessel typically contains marine seismic surveyequipment, such as navigation control, seismic source control, seismicreceiver control, and recording equipment. The seismic source controlmay cause the one or more seismic sources, which are typically air gunsor marine vibrators, to produce acoustic signals at selected times(often referred to as “firing a shot” or “shooting”).

Each acoustic signal is essentially a sound wave that travels downthrough the water and into the subterranean formation. At each interfacebetween different types of rock or other formations of differingcomposition, a portion of the sound wave may be refracted, a portion ofthe sound wave may be transmitted, and another portion may be reflectedback toward the body of water to propagate toward the surface. Thestreamers towed behind the vessel are generally elongated cable-likestructures. Each streamer includes a number of seismic receivers thatdetect pressure and/or particle motion changes in the water created bythe sound waves reflected back into the water from the subterraneanformations. The seismic receivers thereby measure a wavefield that wasultimately initiated by the triggering of the seismic source.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A-1B illustrate coordinates and terminology associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 2 illustrates diagrams of a recording after splicing and spatialshift of recorded seismic data according to one or more embodiments ofthe present disclosure.

FIG. 3 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 4 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 5 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 6 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 7 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 8 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 9 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 10 illustrates a diagram of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure.

FIG. 11 illustrates a diagram of a system for seismic data acquisitionand/or seismic data processing according to one or more embodiments ofthe present disclosure.

FIG. 12 illustrates a diagram of a machine for seismic data acquisitionand/or seismic data processing according to one or more embodiments ofthe present disclosure.

FIG. 13 illustrates an example method for seismic data processingaccording to one or more embodiments of the present disclosure.

FIG. 14 illustrates an example method for seismic data processingaccording to one or more embodiments of the present disclosure.

FIG. 15 illustrates an example method for seismic data processingaccording to one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

The present disclosure is related to seismic data acquisition and/orprocessing with source signal emission sequences and continuous and/ornear-continuous recording. Embodiments of the present disclosure allowfor acquisition and/or processing of seismic data with fewer limitationson minimum shot intervals (time between shots), minimum record lengths,and/or maximum acquisition speeds as compared to other approaches ofseismic data acquisition and/or processing. Further, embodiments of thepresent disclosure allow for emitting signals from sources, such as oneor more source elements, as described herein, without an allotted and/orrequired listening period between shots. Embodiments of the presentdisclosure further allow for source triggering based on time, ratherthan position. Seismic data are recorded continuously ornear-continuously and positions of source elements and/or seismicreceivers can be derived as a function of time. For example, thepositions of the source elements and/or the seismic receivers can bederived based on seismic data input from one or more navigation systemsof a marine seismic survey vessel, the positions of the source elementsand/or the seismic receivers determined as a function of time relativeto a start time of the continuous or near-continuous recording.

It is to be understood the present disclosure is not limited toparticular devices or methods, which may vary. It is also to beunderstood that the terminology used herein is for the purpose ofdescribing particular embodiments only, and is not intended to belimiting. As used herein, the singular forms “a”, “an”, and “the”include singular and plural referents unless the content clearlydictates otherwise. Furthermore, the words “can” and “may” are usedthroughout this application in a permissive sense (i.e., having thepotential to, being able to), not in a mandatory sense (i.e., must). Theterm “include,” and derivations thereof, mean “including, but notlimited to.” The term “coupled” means directly or indirectly connected.

The figures herein follow a numbering convention in which the firstdigit or digits correspond to the drawing figure number and theremaining digits identify an element or component in the drawing.Similar elements or components between different figures may beidentified by the use of similar digits. As will be appreciated,elements shown in the various embodiments herein can be added,exchanged, and/or eliminated so as to provide a number of additionalembodiments of the present disclosure. In addition, as will beappreciated, the proportion and the relative scale of the elementsprovided in the figures are intended to illustrate certain embodimentsof the present invention, and should not be taken in a limiting sense.

This disclosure is related generally to the field of marine seismicsurveying. For example, this disclosure may have applications in marineseismic surveying, in which one or more towed sources are used togenerate wavefields, and seismic receivers—either towed or oceanbottom—receive reflected seismic energy generated by the seismicsources. The disclosure may also have application to the acquisitionand/or processing of seismic data in marine seismic surveying.

FIGS. 1A-1B illustrate coordinates and terminology associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. FIG. 1A illustrates anelevation or xz-plane 119 view of an example marine seismic surveyvessel 109 towing a source 103 and a streamer 113 located beneath a freesurface 115. In various embodiments, the source 103 can include one ormore air guns and/or marine vibrators, among others, as source elements.In practice, source 103 and streamer 113 may be towed by the same ordifferent vessels. FIG. 1A represents a snapshot, at an instant in time,of the undulating free surface 115 and corresponding smooth wave-likeshape in the streamer 113. FIG. 1B includes xy-plane 117 and FIG. 1Aincludes an xz-plane 119 of the same Cartesian coordinate system used tospecify coordinate locations within the fluid volume with respect tothree orthogonal, spatial coordinate axes labeled x, y and z. The xcoordinate uniquely specifies the position of a point in a directionparallel to the route of travel of the vessel 109 at a particular pointin time, and the y coordinate uniquely specifies the position of a pointin a direction perpendicular to the x axis and substantially parallel tothe free surface 115 at vessel 109, and the z coordinate uniquelyspecifies the position of a point perpendicular to the xy-plane 117 at aparticular point in time. The geoid 123 is the hypothetical surface ofthe sea level at vessel 109 and is used to define zero elevation (i.e.,z=0). Shaded disks, such as shaded disks 105-1 and 105-2, representseismic receivers spaced along streamer 113. Seismic receivers 105 caninclude, for instance, seismic receivers and/or electromagneticreceivers, among others. Although illustrated on a towed streamer 113,the seismic receivers 105 may be located on a number of ocean bottomcables (OBCs) and/or on nodes attached near or on the water bottom.

FIG. 1A includes an illustration of a shot and wave routes 129-1, 129-2from the source 103 at a corresponding number of seismic receivers105-1, 105-2. Also illustrated at the corresponding number of seismicreceivers 105-1, 105-2 is arrival of a corresponding number of signals127-1, 127-2 from the source 103 reflected off the free surface 115. Asused herein, “source-side” can refer to some action, item, or eventassociated with the source (not with the seismic receiver), affecting asource, and/or positioned near or in the same location as the source,among others. “Receiver-side” can refer to the same association ofactions, items, or events with a seismic receiver. FIG. 1A illustratesup-going wavefield 133 and down-going wavefield direction 135, asdiscussed further herein.

FIG. 1B illustrates a top or xy-plane 117 view of the marine seismicsurvey vessel 109 towing a source 103 with source elements 103-1, 103-2,103-3 and four separate streamers 113-1, 113-2, 113-3, 113-4 locatedbeneath a free surface. Embodiments are not limited to three sourceelements in a source, as a source can include more or fewer sourceelements. Some embodiments can, for example, include 35 source elementsin the source. Furthermore, the source can be one-dimensional (e.g.,arranged in a line as shown), two-dimensional (e.g., arranged in arectangular grid), or three-dimensional (e.g., arranged in a cube),which can be termed an array of source elements or a source array.Source 103 may be a number of types including, but not limited to asmall explosive charge, an electric spark or arc, a marine vibrator,and/or a seismic source gun, such as an air gun, among others. Source103 may comprise a number of source elements in a source configuration,and can, without limitation, generate a short-duration impulse.

Embodiments are not limited to a particular number of streamers and caninclude more or fewer than are shown in FIG. 1B. Some embodiments can,for example, include 24 or more streamers. As illustrated, the streamers113-1, 113-2, 113-3, 113-4 can be modeled as a planar horizontalacquisition surface located beneath the free surface. However inpractice, the acquisition surface can be smoothly varying due to activesea currents and/or weather conditions. In other words, the towedstreamers may also undulate as a result of dynamic conditions of thefluid. The coordinates of a particular seismic receiver are given by (x,y, z) taking into account both the xz-plane 119 and the xy-plane 117. Insome embodiments, the seismic receiver array may vary in the zdirection. For example, streamers may be slanted such that seismicreceivers disposed farther from the vessel may be deeper than thosecloser to the vessel. Likewise, in some embodiments, one or more of thestreamers may be towed at a different depth than other streamers,thereby creating an acquisition volume.

Although not illustrated, the marine seismic survey vessel 109 mayinclude equipment, referred to herein generally as a “recording system”,that may provide and/or include navigation control, navigationmonitoring, including position determination, seismic source control,seismic source monitoring, seismic receiver control, seismic receivermonitoring, seismic data recording, time monitoring, and/or timesynchronization between the various control, monitoring, and/orrecording elements.

Although FIGS. 1A and 1B illustrate horizontal and/or straight-linetowing, examples of the present disclosure may include circular towingand/or spiral towing, among other patterns. Although FIGS. 1A and 1Billustrate a single vessel, a plurality of vessels may be present, withsome or all of the vessels towing streamers and some or all of thevessels triggering sources. The streamers may be towed in differentdirections, depths, and/or angles, among other differences.

Seismic data acquisition in accordance with one or more embodiments ofthe present disclosure may be applicable to a plurality of seismic dataacquisition operations, including towed marine seismic, ocean bottomseismic, land seismic, among other implementations, and/or combinationsthereof. In embodiments utilizing ocean bottom nodes and/or OBCs, towedsources can be triggered and the resultant wavefield can be detectedwith nodal data receivers positioned on the water bottom.

Seismic data acquisition in accordance with the present disclosure canalso include the use of a single seismic streamer or an OBC. Examples ofthe present disclosure can also be used with three-dimensional seismicdata acquisition techniques, in which, for example, more than oneseismic source and/or laterally spaced streamers and/or OBCs are used toacquire seismic data.

In some examples, a vessel can tow a source that can be triggered atselected times. In some examples, a streamer is also towed by thevessel. The streamer includes seismic receivers at spaced positionsalong the cable. Each seismic receiver can detect pressure and/orparticle motion in the water and/or can be responsive to changes in thepressure and/or particle motion with respect to time.

In some embodiments, an OBC can include seismic receivers spaced alongthe OBC. Signals generated by the seismic receivers can be recorded by arecording unit for later retrieval and/or processing.

When a source is triggered, some acoustic energy travels downwardly.Some of the downwardly traveling energy can be reflected from the waterbottom, whereupon the reflected energy travels upwardly. Some of thedownwardly traveling energy also penetrates the water bottom and mayreach a subsurface layer boundary. Acoustic energy may be reflected fromthe subsurface layer boundary, whereupon the reflected energy travelsupwardly. The upwardly traveling acoustic energy can be detected by theseismic receivers on the streamer (or the receivers on nodes and/or anOBC at or near the water bottom if any are used). The upwardly travelingenergy may reflect from the water surface, whereupon the energy travelsdownwardly again. The water surface reflected energy can be detected bythe seismic receivers, resulting in a ghost signal. The water surfacereflected energy also may be reflected from the water bottom and therebybecome upwardly traveling energy. Further, acoustic energy can reflectfrom the water surface (becoming down-going energy) and can againreflect from the water bottom (becoming up-going energy) a plurality oftimes, resulting in water-layer multiple reflections.

As a result of all the foregoing acoustic energy interactions with thewater and the structures below the water, the acoustic energy detectedby the seismic receivers, referred to as a “total wavefield”, includesboth the upwardly traveling energy (an up-going wavefleld) and thedownwardly traveling energy (a down-going wavefield). The up-going anddown-going wavefields can include components resulting from subsurfacereflectors and/or from water surface and water bottom reflections.

Common approaches to seismic data acquisition include synchronizedrecording of seismic data and firing of sources, and the triggering ofthe sources based on position. In such approaches, the recording startsshortly before or at the time when the sources are triggered, and thelength of the records in time is defined such that it is less than thetime it takes to move the vessel from one source position (or “shotpoint”) to the next. This has meant that the shorter the spacing betweenthe shot points, the less the recording time. Also, the acquisitionspeed may be limited by the defined record length and distance betweenshots. Further, a record length may need to be known before recordingbegins, and this length may stay the same throughout recording.

In contrast, as described herein, near-continuous recording may includeno concept of individual records tied to shot points, and the start ofthe seismic recording may no longer be determined by source position. Asused herein, “near-continuous” can include without meaningful breaks inthe seismic recording. As would be understood by one of ordinary skillin the art with the benefit of this disclosure, operationalcircumstances can cause intermittent gaps in records (due to equipmentfailure, etc.), and “near-continuous recording” should be read toinclude records with intermittent or periodic gaps, whether planned orunplanned as well as records without intermittent or periodic gaps, thusincluding “continuous records.” For simplicity, the term“near-continuous” and “near-continuously” will be used herein and do notexclude “continuous” or “continuously”. The seismic data is recordednear-continuously and can be split into records (data samples) ofdesired length, possibly on board the vessel and/or during onshoreprocessing. From these records it may be possible to splice recordstogether to make longer near-continuous records. To enable suchsplicing, the beginning and/or end times of the records can besynchronized relative to a standard clock time, as described herein.

When the common approaches to seismic data acquisition use sources thatare triggered based on position and/or positions with a specifiedspacing, there may be a required minimum listening time after thesources have stopped emitting signals. If sources are triggered in atime distributed fashion where a firing sequence is initiated based onposition, the firing sequence has to be completed before the source hasmoved to the next shot point, where a firing sequence is initiatedagain. This may cause limitations in maximum acquisition speed. Forinstance, if the desired spacing between shot points is 25 m, and theminimum time between the shot points is 10 seconds, then the maximumspeed the seismic vessel can typically move forward is 2.5 m/s.Triggering the sources in this way may limit how much energy can be putinto the ground per unit of time.

Furthermore, it normally takes less time to recharge the sources thanthe travel time between shot points, so the triggering of sources basedon position may be limiting in terms of how much energy can be put intothe ground in total. In addition, sources may consist of a plurality ofsource elements in an array that may be triggered simultaneously toproduce the maximum possible peak output. This method of operation maynot be very environmentally friendly because a lot of energy is emittedin very short time periods. Triggering source based on position mayresult in shot records of limited rates, so any operators applied to therecords may result in edge effects at the beginning and/or end of therecords.

In contrast, embodiments of the present disclosure can includetriggering sources based on time, not position. In some embodiments,this may result in a smaller time interval between each source trigger.In some embodiments, there may not be a required listening time after asource has finished emitting signals. This can allow for theunrestricted signal emission and/or shot firing, in some examples.Further, single source elements may be triggered individually, or anumber of source elements may be triggered simultaneously or in acoordinated sequence. Processing the seismic data acquired in accordancewith the present disclosure may include determination of a sequence ofsource triggering times. In addition, the position of each sourceelement and the wavefield or wavefields emitted therefrom may bedetermined as a function of time. Moreover, the position of each of theseismic receivers also may be determined as a function of time.

Seismic data acquired from the seismic receivers can be recorded in anear-continuous fashion such that it is possible to make records withnear-continuous seismic data. As described herein, the times of therecorded seismic data samples, the times when sources are triggered,and/or the positions of the source elements and/or seismic receivers asa function of time can be accurately determined and/or interrelated bythese times being synchronized. This near-continuous seismic data can behandled with fewer edge effects and record length restrictions ascompared to other approaches.

Embodiments of the present disclosure may allow for alternatives forfiring all source elements at once. For instance, in a number ofexamples, instead of firing all source elements in a source arraysimultaneously, the source elements or a subset of the source elementsmay be triggered in sequences spread out over time. This means that theinstantaneous maximum pressure levels and the sound pressure levels canbe reduced as compared to other approaches. This may ameliorate someenvironmental concerns related to seismic surveying.

Furthermore, in some examples in accordance with the present disclosure,there may be few or no limits in terms of minimum shot intervals,minimum record lengths, and/or maximum acquisition speeds. Therefore,the acquisition speed can be faster than other approaches withconsequential time and/or efficiency savings. Seismic data acquired assuch may be more accurate due to the closer spatial relationships.

In some instances, air compressor capacity that is available on a towingvessel can be better utilized as compared to other approaches. Becausethere may be few or no restrictions on listening time after a source hasbeen triggered, and because a subset of the available source elementsmay be triggered in predetermined sequences spread over time, theonboard air compressors may not need to recharge as large a volume inthe source elements for every shot. As a result, the total energyemitted in a survey may be increased and/or the signal to noise ratio(S/N) may be improved across the frequency band, including ultra-lowfrequencies.

In some examples of the present disclosure, during the processing ofseismic data, a depth range of a resulting seismic image can be chosenand may be larger than in other seismic data acquisition and/orprocessing approaches with a fixed record length. In a number ofexamples, sources can be triggered at higher spatial densities ascompared to other approaches and/or the shot intervals can be chosenduring processing to have a finer spacing than in other approaches. Themethods described herein may be applicable to a plurality of seismicdata acquisition techniques, including towed marine seismic, oceanbottom seismic, and/or land seismic, among others. More details withregard to how the seismic data acquisition may be performed, and how theresulting seismic data may be processed will be discussed furtherherein.

For instance, in some example embodiments, acquisition of seismic datamay include recording of seismic data from geophysical receivers. Asdescribed herein, these receivers can include ocean bottom receivers,land receivers, and/or receivers located on a towed streamer. As such,embodiments can include, towing at least one streamer and a plurality ofsource elements behind a vessel in a body of water, where the seismicreceivers are located on the towed streamer. As used herein, the term“receiver” is intended to mean “seismic receiver” unless describedotherwise. The receivers can include hydrophones, geophones, pressuresensors, particle motion sensors, among other types of seismic sensors,and/or combinations thereof. That is, in various embodiments, at leasttwo of the plurality of source elements can be different types of sourceelements.

The recording of the seismic data from the receivers can start beforethe first source is triggered, and the recording system cannear-continuously record the seismic data from a plurality of seismicreceivers. The seismic data may be split up into records (data samples)of limited length, such that it is possible to splice the recordstogether to create a near-continuous record. The positions of the sourceelements and/or the receivers as a function of time relative to thestart time of the near-continuous recording can be determined, forexample, based on data input from the navigation systems as monitored bythe recording system. The positions may have a sufficient density suchthat they are not aliased in a spatial or temporal sense. In otherwords, positions for every time sample in the seismic records may not beneeded, provided that such information can be interpolated from theavailable positions without ambiguity. Rather a portion of the positionsfor each source element can be determined and others interpolated.

Different source elements may be triggered at predefined times relativeto the start of the near-continuous recording. For example, thenear-continuously recording of seismic data received from a plurality ofreceivers can start prior to triggering of any of the source elements.The time interval between triggering source elements may be very short,such as only a few milliseconds, and, in some instances, triggering ofthe source elements may not be regularly distributed in time (withequal-sized time intervals) and/or the source element positions may notbe regularly spaced (with equal-sized separations). The time intervalscan be random or pseudorandom, for instance. In some examples of towedreceivers, the towing vessel can move at any speed, as shot pointtriggering can be based on time, not position. The depths of the shotpoint may be different, for example, between about 5 and about 15meters, such that in the case of marine seismic surveys, diversity ofthe ghost from the desired seismic data can be achieved to enable arobust de-ghosting. As it applies to marine seismic data acquisition, aghost effect can result from reflections from the sea surface. Ghostreflections can interfere with primary reflections, limiting useablebandwidth and/or data integrity.

In an example embodiment, for each source element that is triggered, thefollowing information may be determined: which source element wastriggered; the time it started to emit signals; the wavefield that wasemitted, (which may be determined based on supplementary informationsuch as near-field hydrophone recordings or on some form ofmodeling/signature estimation based on measurements of air pressure inthe guns, atmospheric pressure, water temperature at the gun depths,volume of air released and/or depth of the source elements, etc., in thecase of air guns); the depth of each source element as a function oftime; and/or the position of each source element as a function of time.

As noted, it may not be necessary to know the position of the shotpoints at each time sample in the recorded seismic data or exactly atthe time when each source element is triggered, provided that thepositions of the source elements are sampled with sufficient densityboth in a temporal and spatial sense such that they can be interpolatedto the time of interest. In a number of examples, clocks on the seismicdata recording, source controller, and/or navigation systems, andpossibly others, may be synchronized accurately by the recording systemsuch that the times from the different systems can be related to eachother. Accordingly, in some embodiments, the positions of the sourceelements and/or the seismic receivers can be derived based on data inputfrom one or more navigation systems of a marine seismic survey vessel,the positions of the source elements and/or the seismic receiversdetermined entirely as a function of time relative to a start time ofthe near-continuous recording.

In order to produce an image of the sub-surface, the recorded seismicdata can be processed. One example approach includes performing a directimaging of the seismic data using a Separated Wavefield IMaging (SWIM)approach. For instance, both up-going and down-going wavefields recordedby a receiver can be used to yield seismic images based upon surfacemultiples. This can provide complementary and useful images at aplurality of target depths. Shallow geophysical analysis may bepossible, for example, even in areas of very shallow water. Deep imagingaround and/or below salt bodies and other complex geology may beimproved, particularly for multi-vessel survey scenarios, includingwide-azimuth, full-azimuth, etc. Incorporation of surface multiples intothe imaging process can also improve subsurface illumination, in anumber of examples.

Other example embodiments can be used to process the recorded seismicdata. While the following example approach is described in a particularorder, no specific order is necessary for processing the recordedseismic data.

If the recorded seismic data from the receivers are split up intorecords of limited lengths in time, the records can be spliced togethersuch that the seismic data that has been recorded in a given receiverposition is included in the same trace. In some examples, the givenreceiver position can include all the seismic data that has beenrecorded in a given receiver position. In contrast to other approaches,this can allow for a near-continuous record, rather than multiple,time-incremented individual records.

If seismic data recorded near-continuously have been split into recordsof limited lengths, all seismic data originally recodednear-continuously may be spliced together into one record. In the caseof towed streamers, in which the receivers are near-continuously movingas a function of time, it may be useful to perform a spatial shift foreach time sample to put the seismic data samples into the receiverpositions at the time they were recorded. In some instances, for someseismic data acquisition methodologies where the receivers are locatedin fixed positions for the entire duration of the near-continuousrecord, such a spatial correction may not be applicable. An example ofseismic data after many seismic records have been spliced together andafter a spatial correction has been applied to each time sample isillustrated in FIG. 2.

FIG. 2 illustrates diagrams 200-1, 200-2, and 200-3 of a recording aftersplicing and spatial shift of recorded seismic data according to one ormore embodiments of the present disclosure. Diagram 200-1 illustrates anexample of an entire near-continuous record after spatial shifts tocorrect for motion of the receivers. The examples illustrated in FIG. 2include seismic data received from one common receiver at a plurality ofdifferent source positions over time. For instance, FIG. 2 includes manyseconds of seismic data at one receiver position. Diagram 200-2illustrates a zoom of a particular time period of the record shown indiagram 200-1. Diagram 200-3 illustrates a different zoom of aparticular time period of the record shown in diagram 200-1.

In the examples illustrated in FIG. 2, the x-axes 203-1, 203-2, and203-3 can represent a spatial position of the receivers, and the y-axes201-1, 201-2, and 201-3 can represent time. For example, the vessel withits streamer towed behind moves a greater distance in diagram 200-1 ascompared to diagram 200-3 because diagram 200-1 represents a longer timeperiod than diagram 200-3. Diagrams 200-1, 200-2, and 200-3 do notinclude the same aspect ratios.

The aforementioned spatial shift can be performed using an operatorapplied to the seismic data in a wavenumber-time domain. The spatialshift includes shifting the seismic data spatially in an x-direction,and the operator can include:O(k _(x) ,t)=e ^(−ik) ^(x) ^(Δx) ^(i)   (1)where k_(x) is the horizontal wavenumber in the x-direction (typicallyin-line), and Δx_(i) is the distance the receiver has moved in thex-direction at time t relative to the start of the near-continuousrecording. This operator can be applied as a complex multiplication inthe wavenumber-time domain, and the seismic data can be transformed backto space and time through an inverse Fourier transform.

In a number of embodiments, after this spatial shift as a function oftime, the seismic data can be organized such that each trace representsseismic data from one common receiver position in the x-direction. Anyreceiver-based operations, such as wavefield separation or receiver sidede-ghosting, may be performed at this point. This organization of theseismic data into one near-continuous record may reduce edge effects ascompared to conventional methods of organizing and/or processing theseismic data in individual records of limited lengths.

FIG. 3 illustrates a diagram 359 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. As illustrated in FIG. 3and within box 355, one trace 357 in one common receiver position 312may contain seismic data from a plurality of source elements 314-1,314-2, . . . , 314-n triggered at different times relative to the startof the common receiver trace. In some examples, the common receiverposition 312 can include the time it takes an entire receiver to betowed through that particular position. For instance, this could take anestimated 2,000 to 3,000 seconds in some examples. As illustrated inFIG. 3, y-axis 304 can represent a time when a source element istriggered, and x-axis 306 can represent the source element position.Pressure variation at receiver position 312 is illustrated as line 310,while an interface of the subsurface can be illustrated by line 308, forexample.

FIG. 4 illustrates a diagram 420 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. As illustrated in FIG. 4and within box 455, one trace 457 in one common receiver position 412may contain seismic data from a plurality of source elements 414-1,414-2, . . . , 414-n triggered at different times relative to the startof the common receiver trace. For instance, y-axis 404 can represent atime when a source element is triggered, and x-axis 406 can representthe source element position. Source elements 414-1, 414-2, . . . , 414-ncan be grouped into source arrays 416-1, 416-2, . . . , 416-m (X_(s)8, .. . , X_(s)1) triggered in different positions with source elementstriggered at different times. If the time when each source element wastriggered is known, and its position in addition to the wavefield itemitted is determined, the wavefield emitted from each source array canbe calculated and/or corrected into a wavefield as if it was emittedfrom a single point in space and time. In some examples, this may bestable only if there are no deep notches in the total wavefield emittedby the source array. As noted, groups of source elements 414-1, 414-2, .. . , 414-n can be considered as source arrays in different spatialpositions relative to the common receiver position 412, and the spatialinformation can be contained along the time axis 404 of the commonreceiver trace 457. For instance, source array 416-3 can include sourceelements 414-3, 414-4, and 414-5. In some examples, different sourcearrays can overlap and include common points, e.g., array 416-6 andarray 416-7 both include source element 414-8. Each source array caninclude information associated with different source positions relativeto the common receiver position.

Similar to FIG. 3, y-axis 404 can represent a time when a source elementis triggered, and x-axis 406 can represent the source element position.Pressure variation at receiver position 412 is illustrated as line 410,while an interface of the subsurface can be illustrated by line 408, forexample. Source arrays 416-1, 416-2, . . . , 416-m may be consistent orinconsistent in size, and can be a plurality of different sizes, e.g., 3source elements, 50 source elements, 100 source elements, etc., forinstance, depending on how they are triggered.

FIG. 5 illustrates a diagram 524 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. In order to determinewhich source elements are included in a particular source array, a tracecan be divided into time windows. As illustrated in FIG. 5, a limitedtime window 526 of a common receiver trace has been contributed to by aspecific set of source elements 514-1, 514-2, 514-m. These sourceelements 514-1, 514-2, 514-m may be considered as a source arrayincluding any number of source elements at different positions triggeredat different times. The number of source elements contributing to anywindow may depend on the window length and/or position. The sourceelements may be triggered at unequal time intervals, so it may be that aslightly different number of sources may fall into each window 526 (offixed length) as it moves down the trace. The limited time window 526can allow for seismic data to be transformed into the source array, withthe appearance that all of the source elements 514-1, 514-2, 514-m weretriggered at the same time. Similar to FIGS. 3 and 4, y-axis 504 canrepresent a time when a source element is triggered, and x-axis 506 canrepresent the source element position. Pressure variation at receiverposition 512 is illustrated as line 510, while an interface of thesubsurface can be illustrated by line 508, for example.

An operator can be defined to transform the recorded seismic data in thetime window to seismic data that would have been recorded had the sourceelements been triggered at the same time; for instance, a new array canbe calculated. If the wavefield emitted by each source element isS_(n)(ω) and the time each source element was triggered relative to thestart time of the common receiver trace is Δt_(n), then an operator maybe applied to the time window of the common receiver trace to convertthe wavefield emitted by this source array into a wavefield emitted by asource array including the same number of source elements in the samespatial positions each emitting a spike of the same amplitude andtriggered at the same time. The operator may be applied as follows:

$\begin{matrix}{{O(\omega)} = \frac{1}{\Sigma_{n}{S_{n}(\omega)}e^{{- i}\;{\omega\Delta}\; t_{n}}}} & (2)\end{matrix}$

Alternatively, the correction may be applied using a least squaresapproach:

$\begin{matrix}{{O(\omega)} = \frac{\Sigma_{n}{{\overset{\_}{S}}_{n}(\omega)}e^{i\;{\omega\Delta}\; t_{n}}}{{{\Sigma_{n}{S_{n}(\omega)}e^{{- i}\;{\omega\Delta}\; t_{n}}}}^{2} + \varepsilon}} & (3)\end{matrix}$The overbar denotes the complex conjugate, and ε is a stabilizationparameter to avoid division by zero. A band pass filter may be appliedin addition, to band limit the output. The operator can be applied as acomplex multiplication in the frequency domain, and then the seismicdata can be transformed back to time.

FIG. 6 illustrates a diagram 630 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. Diagram 630 includesseismic data resulting from the operator in Equation (2) or (3) beingapplied. As illustrated, the operator O(ω) can convert the wavefieldemitted from this source array including source elements 614-1, 614-2,and 614-m triggered at different times, each with a wavefield emittedthat is S_(n)(ω), into a wavefield emitted from an array in the samespatial position including source elements triggered at the same timeeach emitting a spike (or some desired band-limited wavelet). Forinstance, limited time window 632 can be illustrated as a resultingtrace with a same spatial position for source elements 614-1, 614-2, and614-m. Similar to FIG. 5, y-axis 604 can represent a time when a sourceelement is triggered, and x-axis 606 can represent the source elementposition. An interface of the subsurface can be illustrated by line 608.

FIGS. 7 and 8 illustrate how methods described with respect to FIGS. 5and 6 can be repeated for a different time window to end up with onesource array in a different spatial position relative to the commonreceiver position.

For example, FIG. 7 illustrates a diagram 761 of example seismic dataassociated with seismic data acquisition and/or seismic data processingaccording to one or more embodiments of the present disclosure. Asillustrated in FIG. 7, a second time window 736 of the common receivertrace can be considered, with some different source elements 714-1,714-2, and 714-m in different positions relative to the common receiverposition contributing to window 736. Similar to FIG. 6, y-axis 704 canrepresent a time when a source element is triggered, and x-axis 706 canrepresent the source element position. An interface of the subsurfacecan be illustrated by line 708.

FIG. 8 illustrates a diagram 837 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. As illustrated in FIG. 8,an operator can be derived that converts the wavefield emitted from thesecond source array into a wavefield emitted from another array in thesame spatial position including source elements triggered at the sametime, with each emitting a spike (or some desired band-limited wavelet).Similar to FIG. 7, y-axis 804 can represent a time when a source elementis triggered, and x-axis 806 can represent the source element position.An interface of the subsurface can be illustrated by line 808.

These new arrays, as illustrated in FIGS. 6 and 8, can be used to createa “common receiver gather”. As used herein, a “gather” of seismic datarepresents a set of traces. A common receiver gather is a set of tracesrecorded at a single receiver position, where each trace in the gatherrepresents detection of a wavefield emitted by an individual sourceelement at a particular position, for example, in an array of sourceelements. In some examples, traces from all positions of source elementsin a source array can be collected and combined to create this commonreceiver gather. In contrast, a “common shot gather” is a set of tracesrelated to a single source element position, where each trace in thegather represents seismic data recorded at a different receiverposition.

FIG. 9 illustrates a diagram 940 of example seismic data associated withseismic data acquisition and/or seismic data processing according to oneor more embodiments of the present disclosure. As illustrated in FIG. 9,seismic data from all of the source element positions derived throughmethods associated with FIGS. 5-8 can be gathered into one commonreceiver gather, in which each trace represents the offset or lateraldistance between the common receiver position and each source array. Insome embodiments, the seismic data may be organized such that atwo-dimensional operator may be applied to the seismic data. In someembodiments, the seismic data may be organized such that athree-dimensional operator may be applied to the seismic data. Thespacing between each trace is defined by the time windows chosen, thetime between them, and the vessel speed. The time windows and the sourcearrays output from these steps may be overlapping. However, a differentset of source elements may contribute in each time window in order toend up with source arrays in different positions. This factor may berelated to the shot spacing in time and space of the input seismic data,and defines the minimum spacing between the output source arrays fromthe methods associated with FIGS. 5-8.

The example illustrated in FIG. 9 includes source arrays with pulsesshown on lines 942-1, . . . , 942-p. The seismic data associated withFIG. 9 may allow for correction of wavefields emitted by source arraysincluding multiple source elements in different spatial positions into awavefield emitted from a single point in space. A wavefield emitted froma single point in space may be desired because of improved spatialresolution of the resulting seismic data. This correction will bediscussed further herein with respect to FIG. 10. In a number ofexamples, lines 942-1, . . . , 942-p can represent pressure signalsreceived from a reflector in the common receiver position from differentsource arrays. Axis 904 can be a time axis, and axis 906 is a positionaxis.

An operator that may be applied to the two-dimensional common receivergather in the frequency-wavenumber domain to convert the wavefieldemitted from a source array into a wavefield emitted from a single pointin space without the source ghost may be:

$\begin{matrix}\frac{1}{{\Sigma_{n}\left( {e^{i\; k_{z}z_{n}} + {r\; e^{{- i}\; k_{z}z_{n}}}} \right)}e^{{- i}\; k_{x}x_{n}}} & (4)\end{matrix}$where r is the reflectivity of the sea surface, z_(n) is the depth ofsource element n, x_(n) is the spatial position of source element nrelative to a center of the source array, k_(z) is the horizontalwavenumber in the x direction (in-line), and k_(z) is the verticalwavenumber given by:

$\begin{matrix}{k_{x} = \sqrt{\left( \frac{\omega}{c} \right)^{2} - k_{x}^{2} - k_{y}^{2}}} & (5)\end{matrix}$where c is the propagation velocity of sound in water.

Alternatively, the operator expressed in Equation 4 may be applied usinga least squares approach:

$\begin{matrix}{{O(\omega)} = \frac{{\Sigma_{n}\left( {e^{{- i}\; k_{z}z_{n}} + {r\; e^{i\; k_{z}z_{n}}}} \right)}e^{i\; k_{x}x_{n}}}{{{{\Sigma_{n}\left( {e^{i\; k_{z}z_{n}} + {r\; e^{{- i}\; k_{z}z_{n}}}} \right)}e^{{- i}\; k_{x}x_{n}}}}^{2} + \varepsilon}} & (6)\end{matrix}$

FIG. 10 illustrates a diagram 1050 of example seismic data associatedwith seismic data acquisition and/or seismic data processing accordingto one or more embodiments of the present disclosure. As illustrated inFIG. 10, the wavefields emitted by source arrays can be converted towavefields emitted from single points in space, and effects of theghosts can be deconvolved, for instance, using equation (4) or (6).Two-dimensional de-ghosting of the seismic data can be performed, forinstance, provided there is diversity in the depths of the sourceelements. In some examples, three-dimensional de-ghosting of the seismicdata can be performed.

Diagram 1050 of FIG. 10 includes wavefields emitted from singlepositions in space, for instance, as illustrated by the spikes on lines1052-1, . . . , 1052-s, as compared to the pulses of FIG. 9. In contrastto FIG. 9, lines 1052-1, . . . , 1052-s can represent reflectivity, asopposed to pressure, as de-ghosting has occurred, and the seismic dataincludes wavefields emitted from single points in space rather thansource arrays. In a number of examples, after application of theoperator in the frequency-wavenumber domain, the seismic data may betransformed back to space-time. Operators can be applied to thetwo-dimensional common receiver gather to correct for the responses ofthe source arrays.

Accordingly, a processing system in accordance with a number ofembodiments of the present disclosure can include a number ofnon-transitory machine readable media with instructions executable toperform a number of actions and/or functions. In various embodiments,the processing system can include instructions executable to select aplurality of time windows of a near-continuous record of seismic datacontributed to by a respective plurality of sets of source elements thatdefine a respective first plurality of source arrays, where at least twoof the source elements in each of the plurality of sets of sourceelements are at different positions and are triggered at differenttimes. The processing system can include instructions executable toconvert a respective first wavefield emitted by each of the firstplurality of source arrays into a respective second wavefield as thoughemitted by a respective second source array including a same number ofsource elements in a same spatial position, each emitting spikes of asame amplitude and triggered at a same time. The processing system caninclude instructions executable to create a common receiver gather basedon the respective second wavefield and convert the common receivergather as though emitted from a single point in space.

In various embodiments, the processing system can include instructionsexecutable to convert the common receiver gather by applying an operatorto the common receiver gather based on a reflectivity of a sea surface,a depth of the source elements, a horizontal wavenumber, and/or avertical wavenumber. In various embodiments, the processing system caninclude instructions executable to de-ghost the common receiver gatherbased on the reflectivity of the sea surface, the depth of the sourceelements, the horizontal wavenumber, and/or the vertical wavenumber. Invarious embodiments, the processing system can include instructionsexecutable to create the common receiver gather such that each tracewithin the common receiver gather represents an offset between a commonseismic receiver position and a source array. In various embodiments,the near-continuous record of seismic data can be in split records andthe processing system can include instructions executable to splicetogether the record to produce a trace with seismic data from a singleacquired line.

A number of types of geophysical data may be generated in accordancewith a number of embodiments of the present disclosure. In someembodiments, the geophysical data may include raw or processed datarelated to, for example, near-continuously recording seismic datareceived from a plurality of seismic receivers, triggering a pluralityof source elements, based upon time and not based upon position, at apredefined sequence of times relative to a start of a near-continuousrecording. In some embodiments, the geophysical data may include raw orprocessed data related to, for example, obtaining seismic data acquiredbased upon trigger times and not based upon positions of a plurality oftriggered source elements, where the seismic data includesnear-continuously recorded seismic data in split records. The splitrecords can be spliced together into a single near-continuous record toproduce a trace with seismic data from a single acquired line. Theseismic data can be processed by performing a spatial shift for each ofa number of time samples to correct for motion of a number of seismicreceivers.

Geophysical data may be obtained and stored, that is, recorded, on anon-transitory, tangible machine-readable medium suitable for importingonshore. A geophysical data product may be produced by assembling and/orprocessing the geophysical data offshore (i.e., by equipment on avessel) or onshore (i.e. at a facility on land) either within the UnitedStates or in another country. If the geophysical data product isproduced offshore or in another country, it may be imported onshore to afacility in the United States. In some instances, once onshore in theUnited States, geophysical analysis may be performed on the geophysicaldata product. In some instances, geophysical analysis may be performedon the geophysical data product offshore. For example, seismic dataprocessing can be performed from data offshore to facilitate otherprocessing of the measured seismic data either offshore or onshore.

FIG. 11 illustrates a diagram of an example of a system 1192 for seismicdata acquisition and/or seismic data processing according to the presentdisclosure. As shown in the example of FIG. 11, the system 1192 caninclude a database 1198 accessible by and/or in communication with aplurality of engines 1194. The engines 1194 can include a record engine1196, a determination engine 1197, and an action engine 1199, forexample. The system 1192 can include additional or fewer engines thanillustrated to perform the various actions and/or functions describedherein and embodiments are not limited to the example shown in FIG. 11.The system 1192 can include hardware in the form of transistor logicand/or application specific integrated circuitry (ASICs), firmware,and/or software, in the form of computer or machine readable andexecutable instructions (CRI/MRI). The CRI/MRI can be programinstructions (programming) stored in a computer or machine readablemedium (CRM/MRM) which in cooperation can form a computing device asdiscussed in connection with FIG. 12.

The plurality of engines 1194, such as record engine 1196, determinationengine 1197, and/or action engine 1199, as used herein can include acombination of hardware and software, but at least includes hardwarethat is configured to perform particular functions, tasks, and/oractions. For instance, the engines shown in FIG. 11 are used for seismicdata acquisition and/or seismic data processing.

For example, record engine 1196 can include hardware and/or acombination of hardware and program instructions to near-continuouslyrecord seismic data received from a geophysical receiver and actionengine 1199 can include hardware and/or a combination of hardware andprogram instructions to trigger a plurality of source elements atpredefined intervals relative to the start of the near-continuousrecording. For example, the plurality of source elements can betriggered at predefined irregular time intervals.

The determination engine 1197 can, for example, include hardware and/ora combination of hardware and program instructions to determine for eachsource triggering: which of the plurality of source elements istriggered; at what time each of the plurality of source elements startedto emit signals; a characteristic of a wavefield in the signals emittedby each of the number of source elements; a depth of each of theplurality of the source elements as a function of time; and/or aposition of each of the plurality of source elements as a function oftime. In some examples, at least two of the plurality of source elementsmay be located at different depths. After each of the number of sourceelements completes signal emission there may be no allotted listeningtime. For instance, source elements can be triggered with a shorter timeinterval as compared to other methods. Because example embodiments ofthe present disclosure have little or no allotted listening time,imaging time can be decreased. For instance, other approaches requirelistening times after triggering sources, and this listening timeusually the length in time that will be imaged.

Once acquired, seismic data can be processed using the plurality ofengines 1194. For instance, action engine 1199 can process seismic dataacquired based on trigger times of the plurality of triggered sourceelements. The seismic data can be near-continuously recorded seismicdata. In some instances, when the seismic data is received split into aplurality of records, action engine 1199 can splice together splitnear-continuously recorded seismic data into a near-continuous record.

Processing the seismic data can also include record engine 1196obtaining data, for example, from the one or more navigation systems todetermine positions of the plurality of triggered source elements fromwithin the near-continuous record based on time, and action engine 1199can organize the seismic data such that each near-continuous recordrepresents seismic data from a common receiver direction and can applyan operator to the organized seismic data to convert a common receivergather as though emitted from a single point in space. This can alsoinclude de-ghosting the common receiver gather. Action engine 1199 canapply an operator to the seismic data to shift the seismic dataspatially based on a horizontal wavenumber in a particular direction anda receiver moved in the same direction at a particular time relative tothe start of the near-continuous recording.

In some examples, determination engine 1197 can determine a particulartime window to analyze as a source array based on and includingparticular source elements from within the triggered source elements,where the particular source elements are within the near-continuousrecord. In addition, action engine 1199 can apply an operator to converta respective first wavefield emitted by each of the first plurality ofsource arrays into a respective second wavefield as though emitted by arespective second source array including a same number of sourceelements in a same spatial position, each emitting spikes of a sameamplitude and triggered at a same time.

Based on the respective second wavefield and/or source element positionsderived from the application of the operator to the time window, actionengine 1199 can create a common receiver gather and apply an operator tothe common receiver gather, where the operator is based on areflectivity of a sea surface, a depth of each of the source elementswithin the same number of source elements, a spatial position of each ofthe source elements within the same number of source elements relativeto the center of the source array, a horizontal wavenumber, and/or avertical wavenumber.

Examples of the present disclosure are not limited to the exampleengines shown in FIG. 11 and, in some instances, one or more enginesdescribed may be combined or be a sub-engine of another engine. Further,the engines shown may be remote from one another in a distributedcomputing environment, cloud computing environment, etc.

FIG. 12 illustrates a diagram of an example of a machine 1282 such as acomputing device, for seismic data acquisition and/or seismic dataprocessing according to the present disclosure. The computing device1282 can utilize hardware, software, such as program instructions,firmware, and/or logic to perform a number of functions, as describedherein. The computing device 1282 can be any combination of hardware andprogram instructions configured to share information. The hardware can,for example, include a processing resource 1284 and/or a memory resource1288, such as CRM/MRM, a database, etc. The processing resource 1284, asused herein, can include one or more processors capable of executinginstructions stored by the memory resource 1288. The processing resource1284 may be implemented in a single device or distributed acrossmultiple devices. The program instructions, such as CRI/MRI, can includeinstructions stored on the memory resource 1288 and executable by theprocessing resource 1284 to perform a particular function, task and/oraction, such as seismic data acquisition and/or seismic data processing.

The memory resource 1288 can be a non-transitory CRM/MRM, including oneor more memory components capable of storing instructions that can beexecuted by the processing resource 1284, and may be integrated in asingle device or distributed across multiple devices. Further, memoryresource 1288 may be fully or partially integrated in the same device asprocessing resource 1284 or it may be separate but accessible to thatdevice and processing resource 1284. Thus, it is noted that thecomputing device 1282 may be implemented on a participant device, on aserver device, on a collection of server devices, and/or a combinationof a participant, e.g., user, device and one or more server devices aspart of a distributed computing environment, cloud computingenvironment, etc.

Memory resource 1288 can be in communication with the processingresource 1284 via a communication link, e.g., a path, 1293. Thecommunication link 1293 can provide a wired and/or wireless connectionbetween the processing resource 1284 and the memory resource 1288.

In the example of FIG. 12, the memory resource 1288 can include aplurality of modules, such as record module 1285, determination module1287, and/or action module 1289. As used herein a “module” can includehardware and software, such as program instructions, but includes atleast program instructions that can be executed by a processingresource, such as processing resource 1284, to perform a particulartask, function and/or action, as described herein. The plurality ofmodules can be independent modules or sub-modules of other modules. Asshown in FIG. 12, record module 1285, determination module 1287, andaction module 1289 can be individual modules located on one memoryresource or can be located at separate and distinct memory resourcelocations, such as in a distributed computing environment, cloudcomputing environment, etc.

Each of the plurality of modules can include instructions that whenexecuted by the processing resource 1284 can function as a correspondingengine described in connection with FIG. 11. For example, the recordmodule 1285 can include instructions that when executed by theprocessing resource 1284 can function as the record engine 1196 shown inFIG. 11. The determination module 1287 can include instructions thatwhen executed by the processing resource 1284 can function as thedetermination engine 1197 shown in FIG. 11. In some instances, theaction module 1289 can include instructions that when executed by theprocessing resource 1284 can function as the action engine 1199 shown inFIG. 11. In various embodiments, the record module 1285, thedetermination module 1287, the action module 1289, the processingresource 1284, and/or the memory resource 1288, among other elementsdescribed herein, can be utilized in combination as a recording system,as described herein.

In a number of examples, record module 1285 can near-continuously recordseismic data received from a plurality of receivers. Action module 1289can trigger, at predefined times relative to a start time of anear-continuous recording, a portion of a plurality of source elementsat irregular time intervals and record received results of thetriggering. These recorded results can be used in refining acquisitionand/or processing of the near-continuously recorded seismic data.

Determination module 1287 can, in some embodiments, determine positionsof a portion of the plurality of receivers as a function of timerelative to the start time of the near-continuous recording. Forinstance, the positions of all of the receivers may not be known; ratherthe positions of a portion of the receivers can be determined based ontime. In some examples, determination module 1287 can determine depthsof the receivers as a function of time relative to the start time of thenear-continuous recording. These depths may not all be the same; rather,at least two of the determined depths may be different.

In some examples, determination module 1287 can interpolate thepositions of the portion of the plurality of receivers and/or anotherportion of the plurality of receivers with previously unknown positions.This makes it possible for only a portion of the positions to bedetermined based on time, rather than positions of each of the pluralityof receivers. Action module 1289 can split the near-continuouslyrecorded seismic data into a plurality of lengths and splice the splitseismic data into a near-continuous record. This near-continuous recordcan be used for processing the near-continuously recorded seismic data,in some instances.

Action module 1289 can also, in some examples, synchronize timerecording devices of the near-continuous recording, a source elementcontroller, and navigation systems such that times from differentsystems are related to one another. This synchronization can improveaccuracy in processing of the near-continuously recorded seismic data.Hence, action module 1289 can be part of the recording system.

During processing of seismic data, record module 1285 can receive anear-continuous record of seismic data, and determination module 1287can select a plurality of time windows of a near-continuous record ofseismic data contributed to by a respective plurality of sets of sourceelements that define a respective first plurality of source arrays. Insome examples, at least two of the source elements in each of theplurality of sets of source elements are at different positions and aretriggered at different times.

Action module 1289 can convert a respective first wavefield emitted byeach of the first plurality of source arrays into a respective secondwavefield as though emitted by a respective second source arrayincluding a same number of source elements in a same spatial position,each emitting spikes of a same amplitude and triggered at a same time.Action module 1289 can also create a common receiver gather based on therespective second wavefield to convert the common receiver gather asthough emitted from a single point in space. Action module 1289, in someinstances, can create the common receiver gather such that each tracewithin the common receiver gather represents an offset between a commonreceiver position and a source array.

In some examples, action module 1289 can convert the common receivergather by applying an operator thereto based on a reflectivity of thesea surface, a depth of the source elements, a horizontal wavenumber,and a vertical wavenumber, and similarly, can de-ghost the seismic databased on the reflectivity of the sea surface, the depth of the sourceelements, the horizontal wavenumber, and/or the vertical wavenumber.

As previously noted, in some instances, seismic data may be acquired insplit records. In such instances, record module 1285 can receive theseismic data in split records, and action module 1289 can splice thesplit records together into a single near-continuous record.

Embodiments are not limited to the examples modules shown in FIG. 12 andin some cases a number of modules can operate together to function as aparticular engine. Further, the engines and/or modules of FIGS. 11 and12 can be located in a single system and/or computing device or canreside in separate distinct locations in a distributed network,computing environment, cloud computing environment, etc.

FIG. 13 illustrates an example method 13101 for seismic data processingaccording to one or more embodiments of the present disclosure. As shownat 13104, the method 13101 can include obtaining seismic data acquiredbased upon trigger times and not based upon positions of a plurality oftriggered source elements. The seismic data, in some instances, caninclude near-continuously recorded seismic data in split records. Asshown at 13106, the method 13101 can include splicing the split recordstogether into a single continuous record to produce a trace with seismicdata from a single acquired line. As shown at 13108, the method 13101can include processing the seismic data by performing a spatial shiftfor each of a number of time samples to correct for motion of a numberof seismic receivers. In a number of examples, the method 13101 can beperformed by a machine, such as machine 1282 illustrated in FIG. 12.

As described herein, the method 13101 can include determining for anumber of trigger times a position of each of the plurality of triggeredsource elements and/or a position of each of a number of seismicreceivers as a function of time, where the function of time includesknown times relative to a start of the near-continuous recording. Insome embodiments, the method 13101 can include receiving the seismicdata in split records and splicing the split records together into asingle near-continuous record. In various embodiments, the splicing canproduce a trace with seismic data from a single acquired line, forexample, as illustrated in FIGS. 3-10.

As described herein, processing the seismic data can, in variousembodiments, include obtaining seismic data to determine positions ofthe plurality of triggered source elements from within thenear-continuous record based on time, organizing the seismic data suchthat each near-continuous record represents seismic data from a commonseismic receiver direction, and applying an operator to the organizedseismic data to convert a source array present in the near-continuousrecord into a plurality of source elements. In some embodiments, themethod 13101 can include de-ghosting the seismic data.

As described herein, the method 13101 can include applying an operatorto the seismic data to shift the seismic data spatially based on ahorizontal wavenumber in a particular direction and a receiver moved inthe same direction at a particular time relative to the start of thenear-continuous recording. In various embodiments, the method 13101 caninclude determining a particular time window to analyze as a sourcearray based on and including a number of particular source elements fromwithin the triggered source elements, where the particular sourceelements are within the near-continuous record. The method 13101 caninclude applying an operator to the time window to convert theparticular source elements into the source array including a same numberof source elements, where each source element emits a spike of a sameamplitude and triggered at a same time, and where the operator is basedon the time each source element is triggered relative to the start timeof the near-continuous record. In various embodiments, the method 13101can include creating a common receiver gather based on source elementpositions derived from the application of the operator to the timewindow. The method 13101 can, in various embodiments, include applyingan operator to the common receiver gather, where the operator, asdescribed herein, can be based on a reflectivity of a sea surface, adepth of each of the source elements within the same number of sourceelements, a spatial position of each of the source elements within thesame number of source elements relative to a center of the source array,a horizontal wavenumber, a vertical wavenumber, and/or a depth of eachof the source elements within the same number of source elements.

As described herein, the method 13101 can include performing a spatialshift for each of a number of time samples to correct for motion of anumber of seismic receivers and put seismic data samples into seismicreceiver positions at a time at which the seismic data were recorded.Each of the seismic receiver positions can produce a trace with seismicdata from a single stationary seismic receiver position. As used herein,a “stationary seismic receiver position” does not necessarily mean thatthe physical receiver is stationary, but that the trace represents dataas though received from a receiver position that is stationary. Invarious embodiments, the method 13101 can, for example, includeselecting a time window of the trace including a number of particularsource elements and applying an operator to the time window to define asource array including a same number of source elements each emitting aspike of a same amplitude and triggered at a same time. In variousembodiments, the method 13101 can, for example, include selecting a timewindow of the trace, identifying which particular source elementscontribute to the time window as a function of time, and applying anoperator to transform a wavefield emitted by the identified sourceelements in the time window to another wavefield that would have beenemitted by the identified source elements had the identified sourceelements been triggered at the same time. In various embodiments, thetime window can be moved from a beginning to an end of the trace.

As described herein, the method 13101 can, in various embodiments,include creating for each of a plurality of time windows, one trace in acommon seismic receiver gather based on the seismic data from each timewindow and/or creating for a plurality of time windows, a common seismicreceiver gather based on a trace from each of the plurality of timewindows. The method 13101 can include applying an operator to transforma wavefield emitted by the identified source elements in the time windowto another wavefield that would have been emitted by the identifiedsource elements had the identified source elements been located at asingle point in space. In some embodiments, the method 13101 can includeapplying an operator to de-ghost the seismic data.

FIG. 14 illustrates an example method 14110 for seismic data processingaccording to one or more embodiments of the present disclosure. As shownat 14112, the method 14110 can include obtaining seismic data acquiredbased upon trigger times and not based upon positions of a plurality oftriggered source elements, wherein the seismic data includesnear-continuously recorded seismic data. As shown at 14114, the method14110 can include processing the seismic data by applying an operator tothe seismic data to shift the seismic data spatially in a particulardirection based on a horizontal wavenumber and a distance that a seismicreceiver moved in the particular direction at a time relative to a startof the near-continuous recording.

As described herein, the method 14110 can include organizing the seismicdata such that each trace represents seismic data from a common receiverposition in the particular direction. The method can include de-ghostingthe seismic data based on the common receiver position.

FIG. 15 illustrates an example method 15120 for seismic data processingaccording to one or more embodiments of the present disclosure. As shownat 15122, the method 15120 can include obtaining seismic data acquiredbased upon trigger times and not based upon positions of a plurality oftriggered source elements, wherein the seismic data includesnear-continuously recorded seismic data. As shown at 15124, the method15120 can include processing the seismic data. As shown at 15126,processing can include identifying source elements that contribute toeach of a plurality of time windows of a same length in a trace of theseismic data. As shown at 15128, processing can include applying anoperator to seismic data in each of the plurality of time windows totransform the seismic data as though the source elements were triggeredat a same time, wherein the operator is based on the time each sourceelement is triggered relative to a start time of the near-continuousrecord.

As described herein, the method 15120 can include creating a commonseismic receiver gather based on source element positions derived fromthe application of the operator. The method 15120 can include applyingan operator to the common seismic receiver gather, wherein the operatoris based on a reflectivity of a sea surface, a depth of each of thesource elements, a spatial position of each of the source elementsrelative to a center of the source array, a horizontal wavenumber, avertical wavenumber, and a depth of each of the source elements.

Although specific embodiments have been described above, theseembodiments are not intended to limit the scope of the presentdisclosure, even where only a single embodiment is described withrespect to a particular feature. Examples of features provided in thedisclosure are intended to be illustrative rather than restrictiveunless stated otherwise. The above description is intended to cover suchalternatives, modifications, and equivalents as would be apparent to aperson skilled in the art having the benefit of this disclosure.

The scope of the present disclosure includes any feature or combinationof features disclosed herein (either explicitly or implicitly), or anygeneralization thereof, whether or not it mitigates any or all of theproblems addressed herein. Various advantages of the present disclosurehave been described herein, but embodiments may provide some, all, ornone of such advantages, or may provide other advantages.

In the foregoing Detailed Description, some features are groupedtogether in a single embodiment for the purpose of streamlining thedisclosure. This method of disclosure is not to be interpreted asreflecting an intention that the disclosed embodiments of the presentdisclosure have to use more features than are expressly recited in eachclaim. Rather, as the following claims reflect, inventive subject matterlies in less than all features of a single disclosed embodiment. Thus,the following claims are hereby incorporated into the DetailedDescription, with each claim standing on its own as a separateembodiment.

What is claimed is:
 1. A method, comprising: obtaining, from a number ofseismic receivers, seismic data indicative of a subterranean formationacquired based upon trigger times and not based upon positions of aplurality of triggered source elements, wherein the seismic dataincludes near-continuously recorded seismic data in split records;splicing, by a machine, the split records together into a singlenear-continuous record to produce a trace with seismic data from asingle acquired line; and processing, by the machine, the seismic databy: determining positions of the plurality of triggered source elementsfrom within the near-continuous recorded based on time; performing aspatial shift based on the determined positions of each of the pluralityof triggered source elements and on a distance moved from a previouslocation at a particular time by each of the number of seismic receiversrelative to the start of recording of the near-continuously recordedseismic data for each of a number of particular times to correct formotion of the number of seismic receivers and to yield seismic databetter indicative of the subterranean formation; organizing the seismicdata such that each near-continuous record represents seismic data froma common seismic receiver position; and applying an operator to theorganized seismic data to convert a source array present in thenear-continuous record into a plurality of source elements.
 2. Themethod of claim 1, further comprising determining for a number oftrigger times the seismic receiver positions as a function of time atknown times relative to a start of the near-continuous recording.
 3. Themethod of claim 1, wherein splicing includes producing a respectivetrace for each of the seismic receiver positions; and wherein processingthe seismic data results in the respective trace representing seismicdata as though received from a single stationary seismic receiverposition.
 4. The method of claim 3, further comprising: selecting a timewindow of the trace including contributions of a number of particularsource elements; and applying a different operator to the time window todefine a source array including a same number of source elements eachemitting a spike of a same amplitude and triggered at a same time. 5.The method of claim 3, further comprising: selecting a time window ofthe trace; identifying which particular source elements' triggeringscontribute to the time window as a function of time; and applying anoperator to transform a wavefield emitted by the identified sourceelements' triggerings in the time window to another wavefield that wouldhave been emitted by the identified source elements had the identifiedsource elements been triggered at the same time.
 6. The method of claim5, wherein the time window is moved from a beginning to an end of thetrace.
 7. The method of claim 5, further comprising creating: for eachof a plurality of time windows, one trace in a common seismic receivergather based on the seismic data from each time window; and for aplurality of time windows, a common seismic receiver gather based on atrace from each of the plurality of time windows.
 8. The method of claim7, further comprising applying a different operator to transform awavefield emitted by the identified source elements' triggerings in thetime window to another wavefield that would have been emitted by theidentified source elements had the identified source elements beenlocated at a single point in space.
 9. The method of claim 8, furthercomprising applying another different operator to de-ghost the seismicdata.
 10. A method of generating a geophysical data product, the methodcomprising: obtaining geophysical data by: obtaining, from a number ofseismic receivers, seismic data indicative of a subterranean formationacquired based upon trigger times and not based upon positions of aplurality of triggered source elements, wherein the seismic dataincludes near-continuously recorded seismic data in split records;splicing, by a machine, the split records together into a singlenear-continuous record to produce a trace with seismic data from asingle acquired line; processing the geophysical data to generate ageophysical data product, the processing comprising: determiningpositions of the plurality of triggered source elements from within thenear-continuous record based on time; processing, by the machine, theseismic data by performing a spatial shift based on the determinedpositions of each of the plurality of triggered source elements and adistance moved from a previous location at a particular time by each ofthe number of seismic receivers relative to the start of recording ofthe near-continuously recorded seismic data for each of a number ofparticular times to correct for motion of the number of seismicreceivers and to yield seismic data better indicative of thesubterranean formation; organizing the seismic data such that eachnear-continuous record represents seismic data from a common seismicreceiver position; and applying an operator to the organized seismicdata to convert a source array present in the near-continuous recordinto a plurality of source elements and recording the geophysical dataproduct on a non-transitory machine-readable medium.
 11. The method ofclaim 10, wherein processing the geophysical data comprises processingthe geophysical data offshore or onshore.
 12. The method of claim 1,wherein obtaining seismic data acquired based upon trigger times and notbased upon positions of a plurality of triggered source elements furthercomprises obtaining seismic data acquired based upon trigger times andnot based upon positions of a plurality of triggered impulsive sourceelements.
 13. The method of claim 1, further comprising determining fora number of trigger times a position of each of the plurality oftriggered source elements as a function of time at known times relativeto a start of the near-continuous recording.